U.S. patent number 5,883,053 [Application Number 08/690,543] was granted by the patent office on 1999-03-16 for nitrogen/carbon dioxide combination fracture treatment.
This patent grant is currently assigned to Canadian Fracmaster Ltd.. Invention is credited to Robin Tudor.
United States Patent |
5,883,053 |
Tudor |
March 16, 1999 |
**Please see images for:
( Certificate of Correction ) ** |
Nitrogen/carbon dioxide combination fracture treatment
Abstract
There is provided an improved fluid for fracturing an
underground formation penetrated by a well bore comprising a
mixture of a liquified gas and a gas.
Inventors: |
Tudor; Robin (High River,
CA) |
Assignee: |
Canadian Fracmaster Ltd.
(CA)
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Family
ID: |
4154663 |
Appl.
No.: |
08/690,543 |
Filed: |
July 31, 1996 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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372354 |
Jan 13, 1995 |
5558160 |
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Foreign Application Priority Data
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Nov 14, 1994 [CA] |
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2135719 |
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Current U.S.
Class: |
507/102;
166/280.2; 507/202; 507/922 |
Current CPC
Class: |
C09K
8/80 (20130101); E21B 43/26 (20130101); C09K
8/62 (20130101); C09K 8/70 (20130101); E21B
43/267 (20130101); Y10S 507/922 (20130101) |
Current International
Class: |
C09K
8/60 (20060101); C09K 8/62 (20060101); C09K
8/80 (20060101); E21B 43/26 (20060101); E21B
43/25 (20060101); C09K 007/08 (); E21B
043/26 () |
Field of
Search: |
;507/102,202,922
;166/280,308 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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687.938 |
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Jun 1964 |
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CA |
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745.453 |
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Nov 1966 |
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CA |
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932655 |
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Aug 1973 |
|
CA |
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1034363 |
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Jul 1978 |
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CA |
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1043091 |
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Nov 1978 |
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CA |
|
1134258 |
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Oct 1982 |
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CA |
|
1197977 |
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Dec 1985 |
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CA |
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1241826 |
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Sep 1988 |
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CA |
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1242389 |
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Sep 1988 |
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CA |
|
2094088 |
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Oct 1993 |
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CA |
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Other References
Report (1979) ORNL/TM-6270 from Energy Res. Abstract 4 (10) As
Abstracted by Chem Abstracts 91: 130759. .
"Gas Frac--A New Stimulation Technique Using Liquid Gases," R.E.
Hurst, Society of Petroleum Engineers of AIME, No. SPE 3837
(1972)..
|
Primary Examiner: Tucker; Philip
Attorney, Agent or Firm: Lerner, David, Littenberg, Krumholz
& Mentlik
Parent Case Text
This is a divisional application of Application Ser. No. 08/372,354
filed Jan. 13, 1995 now Pat. No. 5,558,160.
Claims
I claim:
1. A fluid for hydraulically fracturing an underground formation
penetrated by a well bore consisting essentially of a liquified gas
co-mingled with a non-liquified gas, wherein said liquified gas is
liquified carbon dioxide and said non-liquified gas comprises one
or more gases selected from the group consisting of nitrogen, air,
exhaust gas, natural gas or inert gases, and wherein said fluid
further includes proppants wherein said proppants are pressurized
and cooled to substantially the pressure and temperature of said
liquified gas prior to adding said proppants to said liquified
gas.
2. The fluid of claim 1 wherein said proppants are added to said
liquified gas prior to co-mingling of said liquified gas with said
non-liquified gas.
3. The fluid of claim 1 wherein said proppants are present in a
predetermined concentration.
4. The fluid of claim 3 wherein said predetermined concentration of
said proppant may be varied during hydraulic fracturing of said
underground formation.
5. The fluid of claim 2 wherein the temperature of said fluid is
maintained below the critical temperature of said liquified gas
upon injection of said fluid into said well bore.
6. The fluid of claim 4 wherein said concentration of said proppant
varies in the range from an amount in excess of 0 kg/m.sup.3 to
1,550 kg/m.sup.3.
7. The fluid of claim 6 wherein the ratio of said gas to said
liquified gas by volume is variable with the liquified gas being
present at least in an amount sufficient for transport of said
predetermined concentration of proppants.
8. A fluid for fracturing an underground formation penetrated by a
well bore consisting essentially of a predetermined amount of a
liquified gas, a predetermined amount of a non-liquified gas, and a
predetermined concentration of proppants, wherein the ratio of said
predetermined amount of said liquified gas to said predetermined
amount of said non-liquified gas is variable wherein there is at
least sufficient liquid gas for transport of said predetermined
concentration of said proppants, said liquified gas being liquified
carbon dioxide and said non-liquified gas being one or more gases
selected from the group consisting of nitrogen, air, exhaust gas,
natural gas and inert gas, and wherein said proppants are first
pressurized and cooled to substantially the storage pressure and
temperature of said liquified gas prior to introducing said
proppants into said liquified gas.
9. The fluid of claim 8 wherein said proppants are added to said
liquified gas prior to the mixing thereof with said gas.
Description
FIELD OF THE INVENTION
This invention relates to the art of hydraulically fracturing
subterranean earth formations surrounding oil wells, gas wells and
similar bore holes. In particular, this invention relates to
hydraulic fracturing utilizing low temperature-low viscosity
fracture fluids and the co-mingling of a gas or gases with liquid
carbon dioxide as a medium to fracturing of subterranean
formations.
BACKGROUND OF THE INVENTION
Hydraulic fracturing has been widely used for stimulating the
production of crude oil and natural gas from wells completed in
reservoirs of low permeability. Methods employed normally require
the injection of a fracturing fluid containing suspended propping
agents into a well at a rate sufficient to open a fracture in the
exposed formation. Continued pumping of fluid into the well at a
high rate extends the fracture and leads to the build up of a bed
of propping agent particles between the fracture walls. These
particles prevent complete closure of the fracture as the fluid
subsequently leaks off into the adjacent formations and results in
a permeable channel extending from the well bore into the
formations. The conductivity of this channel depends upon the
fracture dimensions, the size of the propping agent particles, the
particle spacing and the confining pressures.
The fluids used in hydraulic fracturing operations must have fluid
loss values sufficiently low to permit build up and maintenance of
the required pressures at reasonable injection rates. This normally
requires that such fluids either have adequate viscosities or other
fluid loss control properties which will reduce leak-off from the
fracture into the pores of the formation.
Fracturing of low permeability reservoirs has always presented the
problem of fluid compatibility with the formation core and
formation fluids, particularly in gas wells. For example, many
formations contain clays which swell when contacted by aqueous
fluids causing restricted permeability, and it is not uncommon to
see reduced flow through gas well cores tested with various
oils.
Another problem encountered in fracturing operations is the
difficulty of total recovery of the fracturing fluid. Fluids left
in the reservoir rock as immobile residual fluids impede the flow
of reservoir gas or fluids to the extent that the benefit of
fracturing is decreased or eliminated. Attempting the removal of
the fracturing fluid may require a large amount of energy and time,
sometimes not completely recovering all the products due to
formation characteristics. Consequently the reduction or
elimination of the problem of fluid recovery and residue removal is
highly desired.
In attempting to overcome fluid loss problems, gelled fluids
prepared with water, diesel, methyl alcohol, solvents and similar
low viscosity liquids have been useful. Such fluids have apparent
viscosities high enough to support the proppant materials without
settling and also high enough to prevent excessive leak-off during
injection. The gelling agents also promote laminar flow under
conditions where turbulent flow would otherwise take place and
hence in some cases, the pressure losses due to fluid friction may
be lower than those obtained with low viscosity-base fluids
containing no additives. Certain water-soluble, poly-acrylamides,
oil soluble poly-isobutylene and other polymers which have little
effect on viscosity when used in low concentration can be added to
the ungelled fluid to achieve good friction reduction.
In attempting to overcome the problem of fluid compatibility when
aqueous fracturing fluids are used, chemical additives have been
used such as salt or chemicals for pH control. Salts such as NaCl,
KCl or CaCl.sub.2 have been widely used in aqueous systems to
reduce potential damage when fracturing water sensitive formations.
Where hydrocarbons are used, light products such as gelled
condensate have seen a wide degree of success, but are restricted
in use due to the nature of certain low permeability
reservoirs.
Low density gases such as CO.sub.2 or N.sub.2 have been used in
attempting to overcome the problem of removing the fracturing
(load) liquid. The low density gases are added to the load fluid at
a calculated ratio which promotes back flow subsequent to
fracturing. This back flow of load fluids is usually due to
reservoir pressure alone without mechanical aid from the surface
because of the reduction of hydrostatic head caused by gasifying
the fluid.
Moreover, low density liquified gases have themselves been used as
fracturing fluids. Reference is made to Canadian Patents 687,938
and 745,453 to Peterson who discloses a method and apparatus for
fracturing underground earth formations using liquid CO.sub.2.
Peterson recognized the advantages of liquid CO.sub.2 as a means to
avoid time consuming and expensive procedures involved in the
recovery of more conventional fracturing fluids. Peterson however
does not disclose the use of entrained proppants in conjunction
with liquid CO.sub.2. The combination of a liquid CO.sub.2
fracturing fluid and propping agents has been described by Bullen
in Canadian Patent 932,655 wherein there is described a method of
entraining proppants in a gelled fluid, typically a gelled
methanol, which is mixed with liquid carbon dioxide and injected
into low permeability formations. The liquid carbon dioxide is
allowed to volatize and bleed off and the residual liquid,
primarily methyl alcohol, is in part dissolved by formation
hydrocarbons and allowed to return to the surface as vapor, the
balance, however, being recovered as a liquid using known recovery
techniques. It has however been demonstrated that the need to use a
gelled carrier fluid has resulted in the negation of some of the
fluid recovery advantages attendant upon the sole use of liquified
gas fracturing fluids.
Subsequent disclosures have been concerned primarily with the
development of more advantageous gelled fluids to entrain proppants
for subsequent or simultaneous blending with the liquified carbon
dioxide fracturing fluid. Reference is made to Canadian Patents
1,000,483 (reissued as Canadian Patent 1,034,363), 1,043,091,
1,197,977, 1,241,826 and 1,242,389 in this regard. Each of these
patents teaches the nature and composition of gelled or ungelled
carrier fluids, typically methanol or water based, which, when
blended with liquid CO.sub.2, produce a two-phase liquid system
which allegedly is useful in attempting to overcome the problems of
leak-off and fluid compatibility with formation fluids while at the
same time being capable of transporting increased concentrations of
proppant material into the fracture zones.
Treatments have also been designed utilizing combinations of fluids
with nitrogen or carbon dioxide and even binary foams where
nitrogen and liquid carbon dioxide are combined into an aqueous or
water-based fracturing fluid. Reference is made in this regard to
U.S. Pat. No. 5,069,283 issued on Dec. 3, 1991 to the Western
Company of North America. The addition of nitrogen and/or liquid
carbon dioxide provides a non-combustible gas that aids in the
recovery of the treatment fluids. These gasified fluids also reduce
the amount of potentially damaging aqueous fluid pumped into the
formation. Despite this, this method nevertheless requires the
incorporation of a thickening agent into the aqueous fluid to
provide sufficient viscosity to entrain adequate proppants and to
prevent leak-off. Although these gasified fluids reduce the amount
of potentially damaging gelled and/or cross-linked load fluid
pumped into the formation, the risk of contamination by significant
residual liquid fractions remains high.
From the foregoing, it will be readily appreciated that the use of
liquid CO.sub.2 as a fracturing agent is known. It is further known
to use other liquids having propping agents entrained therein for
blending with the liquified gas fracturing fluid. The propping
agents are subsequently deposited in the liquid or foam-formed
fractures for the purpose of maintaining flow passages upon rebound
of the fracture zone. It is further known that proppant materials
can be introduced into a liquid carbon dioxide system if a
chemically gelled or cross-linked liquid, usually alcohol or
water-based, is mixed with the CO.sub.2 to impart sufficient
viscosity to the mixture to support proppant particles and to
control leak-off in the fracture. So-called "binary" systems
incorporating additional quantities of nitrogen in a thickened
aqueous substrate are known. All of these practices lead to
residual chemicals and gel precipitates left in the fracture
proppant pack that can impair production of the well.
In Canadian Patent 1,134,258 belonging to the assignee herein, it
has been recognized that proppant materials can be introduced
directly into a liquid carbon dioxide stream using little or no
other viscosifying liquid components while still transporting
significant quantities of up to 800 kg/m.sup.3 (and more in some
situations) of proppant material into the fracture zones. This has
been achieved by pressurizing and cooling the proppants to
substantially the storage pressure and temperature of the liquified
CO.sub.2 prior to blending of the two for injection down the well
bore.
This method, based as it is on the injection of pure or virtually
pure CO.sub.2, enjoys the obvious advantage of lessening the impact
of the treatment fluid on the formation. A gas as mentioned in this
application describes any substance that at atmospheric conditions
exists in the vapour phase of that substance. Liquid CO.sub.2, and
gases such as nitrogen, air, exhaust gas, natural gas and insert
gases, are all relatively inert to the formation being stimulated
and therefore no damage is done to the formation due to injection
since it is believed that CO.sub.2 and the other aforementioned
gases do not change the relative permeability of the reservoir
rock. The liquid CO.sub.2 fracturing medium converts to a gaseous
state after being subjected to formation temperatures and pressures
to eliminate associated fluid pore blockage in the formation and to
promote complete fluid recovery on flow back. Moreover, no residual
chemicals or gel precipitates are left behind to impair fracture
conductivity.
There have been literally hundreds of fracture treatments in Canada
and abroad using 100% liquid CO.sub.2. There have also been
treatments using 100% gaseous nitrogen. A medium consisting solely
of liquified CO.sub.2 and nitrogen has not been used. Reasons
include: dilution of the liquified CO.sub.2 using nitrogen will
obviously even further reduce what little inherent proppant
carrying capacity is possessed by the CO.sub.2, increase of fluid
losses into the formation, and increased surface pumping pressures
from increased friction pressures and decreased hydrostatic head
caused by the addition of nitrogen that will increase costs.
Applicant has discovered however that significant advantages can be
obtained from the co-mingling of gases with liquid CO.sub.2 and,
when combined with the method of Canadian Patent 1,134,258, without
loss of proppant carrying capacity. Moreover, contrary to
expectations, liquid CO.sub.2 /N.sub.2 treatments result in actual
lowering of surface treatment pressures at equivalent volumetric
rates which reduces pumping costs, and yield improved leak-off
characteristics. Significant additional economic benefits accrue as
well as will be discussed below.
SUMMARY OF THE INVENTION
Accordingly, it is an object of the present invention to provide a
fracturing fluid and a method of hydraulic fracturing utilizing a
liquified gas co-mingled with a gas providing both commercially
acceptable proppant deliveries with minimum formation
contamination.
In a preferred aspect of the present invention, these objects are
achieved by adding gaseous nitrogen to a stream of liquified carbon
dioxide including proppants entrained therein.
According to the present invention, then, there is provided a fluid
for fracturing an underground formation penetrated by a well bore
comprising a mixture of a liquified gas and a gas.
According to another aspect of the present invention, there is also
provided a fluid for hydraulically fracturing an underground
formation penetrated by a well bore comprising a liquified gas
co-mingled with a non-liquified gas.
According to yet another aspect of the present invention, there is
also provided a fluid for fracturing an underground formation
penetrated by a well bore comprising a mixture of a predetermined
amount of a liquified gas and a predetermined amount of a
non-liquified gas, the ratio of said predetermined amount of said
liquified gas to said predetermined amount of said non-liquified
gas being variable in a wide range.
According to yet another aspect of the present invention, there is
also provided a fluid for fracturing an underground formation
penetrated by a well bore comprising a mixture of a liquified gas
and a gas.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the invention will now be described in greater
detail and will be better understood when read in conjunction with
the following drawings, in which:
FIG. 1 is a block diagram of the hydraulic fracturing system
combining proppants with liquid CO.sub.2 ;
FIG. 2 is a pressure-temperature plot for CO.sub.2 in the region of
interest with respect to the method of well fracturing illustrated
in FIG. 1;
FIG. 3 is a sectional view taken along the longitudinal axis of the
proppant tank illustrated schematically in FIG. 1;
FIG. 4 is a partially sectional view of the proppant tank of FIG.
3;
FIG. 5 is a more detailed view of the tank of FIGS. 3 and 4;
and
FIG. 6 is a block diagram of the hydraulic fracturing system of the
present invention.
DETAILED DESCRIPTION
It will be appreciated by those skilled in the art that a number of
different liquified gases having suitable viscosities and critical
temperatures may be utilized as fracturing fluids. For purposes of
illustration, however, and having regard to the cost and safety
advantages afforded by the use of carbon dioxide, reference will be
made herein to the use of liquified carbon dioxide as the principal
liquified gas fracturing agent of the present hydraulic fracturing
method.
As the basic method of combining proppant material with liquid
CO.sub.2 referred to in Canadian Patent 1,134,258 is a component of
the present invention, it will be useful to redescribe that process
in considerable detail herein as follows. It will be understood
that the following description is intended to be exemplary in
nature and is not limitative of the present invention. Other means
of combining liquid CO.sub.2 with proppants may occur to those
skilled in the art as will alternative apparati.
Referring to FIGS. 1 and 2 together, liquified CO.sub.2 and
proppants are transported to a well site. At the site, the
liquified CO.sub.2 is initially maintained at an equilibrium
temperature and pressure of approximately -31.degree. C. and at
1,380 kPa (#1 in FIG. 2) in a suitable storage vessel or vessels 10
which may include the transport vehicle(s) used to deliver the
liquified gas to the site. The proppants are also stored in a
pressure vessel 20. The proppants are pressurized and cooled using
some liquid CO.sub.2 from vessels 10 introduced into vessel 20 via
manifold or conduit 5 and tank pressure line 15. In this manner,
the proppants are cooled to a temperature of approximately
-31.degree. C. and subjected to a pressure of approximately 1,380
kPa.
Liquid CO.sub.2 vaporized by the proppant cooling process is vented
off and a 1/2 to 3/4 capacity (FIG. 3) level 24 of liquid CO.sub.2
is constantly maintained in vessel 20 so as to prevent the passage
of vapor downstream to the high pressure pumps 30 used to inject
the fracture fluids into the well bore 40. Pumps 30 are of
conventional or known design so that further details thereof have
been omitted from the present description.
Prior to the commencement of the fracturing process, the liquid
CO.sub.2 stored in vessels 10 is pressured up to approximately
2,070 to 2,410 kPa, that is, about 690 to 1,035 kPa above
equilibrium pressure, so that any pressure drops or temperature
increases in the manifolds or conduits between vessels 10 and pumps
30 will not result in the release of vapor but will be compensated
for to ensure delivery of CO.sub.2 liquid to frac pumps 30. Methods
of pressuring up the liquid CO.sub.2 are well known and need not be
described further here.
Liquified CO.sub.2 is delivered to pumps 30 from vessels 10 along a
suitable manifold or conduit 5. Pumps 30 pressurize the liquified
CO.sub.2 to approximately 17,250 to 68,950 kPa or higher, the
well-head injection pressure. The temperature of the liquid
CO.sub.2 increases slightly as a result of this pressurization.
The horizon to be fractured is isolated and the well casing
adjacent the target horizon is perforated in any known fashion. The
liquid CO.sub.2 is pumped down the well bore 40, through the
perforations formed into the casing and into the formation. With
reference to FIG. 2, the temperature of the CO.sub.2 increases as
it travels down the well bore due to the absorption of heat from
surrounding formations. It will therefore be appreciated that the
CO.sub.2 must be pumped at a sufficient rate to avoid prolonged
exposure of the CO.sub.2 in the well bore to formation heat
sufficient to elevate the temperature of the CO.sub.2 beyond its
critical temperature of approximately 31.degree. C.
Methods of calculating rates of heat adsorption and appropriate
flow rates are well known and therefore will not be elaborated upon
here. It will in any event be appreciated that with continued
injection, the temperature of surrounding pipes and formations are
reduced to thereby minimize vapor losses during injection.
Pressurization of the CO.sub.2 reaches a peak (3) at the casing
perforations and declines gradually as the CO.sub.2 moves laterally
into the surrounding formations. Fracturing is accomplished of
course by the high pressure injection of liquified CO.sub.2 into
the formations. After pumping is terminated the pressure of the
carbon dioxide bleeds off to the initial pressure of the formation
and its temperature rises to the approximate initial temperature of
the formation.
During the fracturing process, of course, the liquified carbon
dioxide continues to absorb heat until its critical temperature
(31.degree. C.) is reached whereupon the carbon dioxide
volatilizes. Volatilization is accompanied by a rapid increase in
CO.sub.2 volume which may result in increased fracturing activity.
The gaseous CO.sub.2 subsequently leaks off or is absorbed into
surrounding formations. When the well is subsequently opened on
flow back, the carbon dioxide exhausts itself uphole due to the
resulting negative pressure gradient between the formation and the
well bore.
As mentioned above, the propping agents are cooled to the
approximate temperature of the liquified CO.sub.2 prior to
introduction of the proppants into the CO.sub.2 stream. The heat
absorbed from the proppants would otherwise vaporize a percentage
of the liquid CO.sub.2, eliminating its ability to adequately
support the proppants at typical pumping rates and which could
create efficiency problems in the high pressure pumpers. The
specific heat of silica sand proppant is approximately 0.84 kj/kg
K. The heat of vaporization of CO.sub.2 at 1,725 kPa is
approximately 232.6 kj/kg. To cool silica sand proppant from a
21.1.degree. C. transport temperature to the liquid CO.sub.2
temperatures of -31.7.degree. C. will therefore require the
vaporization of approximately 0.09 kg of CO.sub.2 for each 0.454 kg
of sand so cooled.
Reference is now made to FIGS. 3 and 4 which illustrates proppant
pressure vessel and blender (tank) 20 in greater detail. The liquid
carbon dioxide used to pressurize and cool the enclosed proppants
is introduced into tank 20 via pressure line 15 and the excess
vapors generated by the cooling process are allowed to escape
through vent 22. Liquid CO.sub.2 operating level 24 prevents an
excess accumulation of vapors and further isolates the vapors from
the proppants transported along the bottom of tank 20 towards the
liquid CO.sub.2 stream passing through conduit 5.
Tank 20 may be fitted with baffle plates 21 to direct the proppants
toward a helically wound auger 26 passing along the bottom of tank
20 in a direction towards conduit 5 via an auger tube 9. Auger
drive means 29 of any suitable type are utilized to rotate auger
26. Auger tube 9 opens downwardly into a chute 8 communicating with
conduit 5 so that proppants entrained along the auger are
introduced into the CO.sub.2 stream passing through the conduit. It
will be appreciated that the pressure maintained in tube 9 equals
or exceeds that in conduit 5 to prevent any blow back of the liquid
CO.sub.2.
It will be appreciated that tank 20 may be of any suitable shape
and feed mechanisms other than the one illustrated utilizing auger
26 may be employed, a number of which, including gravity feed
mechanisms, will occur to those skilled in the art.
After sufficient liquified carbon dioxide has been injected into
the well to create a fracture in the target formation, cooled
proppants from pressurized proppant tank 20 may be introduced into
the streams of liquid carbon dioxide to be carried into the
fracture by the carbon dioxide. The proppants may include silica
sand of 40/60, 20/40 and 10/20 mesh size. Other sizes and the use
of other materials is contemplated depending upon the requirements
of the job at hand.
It will be appreciated that if so desired, cooled proppants may be
introduced into the carbon dioxide stream simultaneously with the
initial introduction of the liquified carbon dioxide into the
formation for fracturing purposes.
Upon completion of fracturing the well may be shut in to allow for
complete vaporization of the carbon dioxide and to allow formation
rebound about the proppants. The well is then opened on flow back
and CO.sub.2 gas is allowed to flow back and exhaust to the
surface.
Turning more specifically now to the present invention, the
methodology involved is similar in outline to that described above
with reference to Canadian Patent 1,134,258, including transport to
the site of liquid CO.sub.2, proppants, gaseous nitrogen storage
vessels for the same and of course high pressure fracture pumpers.
A typical well site equipment layout is illustrated in FIG. 6. The
layout includes a CO.sub.2 supply side comprising one or more
storage vessels or bulkers 10 for liquid CO.sub.2, a pressure
vessel 20 for pressurized storage and blending of the proppants
with CO.sub.2 from vessels 10 and high pressure fracture pumpers 30
for pumping the CO.sub.2 /proppant mixture through high pressure
supply line 40 to the well head 50 and down the well bore. The
layout can additionally include a nitrogen booster 18 for bulker 10
and CO.sub.2 pressure vessel 20.
The nitrogen supply side includes storage vessels 60 for the gas,
and high pressure gas pumpers 70 which pump the gas through supply
line 65 to the intersection 45 with supply line 40.
The intersection 45 in the supply line 40 is the point of initial
contact between the streams of CO.sub.2 and N.sub.2 resulting in
turbulence to form the liquid CO.sub.2 /gas mixture, additional
admixing occurring along the remaining length of supply line 40 and
down the well bore.
As will be apparent, the addition of the gas to the liquid CO.sub.2
stream occurs downstream, in high pressure line 40, from blender 20
and high pressure pumps 30. Blender 20 adds proppant to the liquid
CO.sub.2 volumetrically at a predetermined maximum rate. This
implies that the effective concentration of proppant is inversely
proportional to the liquid CO.sub.2 rate. Moreover, although the
proppant stream is diluted by the addition of gas downstream of
pumpers 30, higher proppant concentrations can be pumped in the
slower liquid CO.sub.2 stream making effective proppant
concentrations approximately equal to standard liquid CO.sub.2
treatments which lack co-mingling of gas.
The optimum ratio of gas to liquid CO.sub.2 is completely variable
with perhaps the only limitation being, when the stream includes
proppants, that there be sufficient CO.sub.2 to transport the
specified proppant quantities. Otherwise, the ratio may be chosen
as a matter of convenience and economics having regard to one or
more factors including depth and temperature of formation to be
treated, distance to well site for transportation costs, relative
cost and availability of gas/CO.sub.2 products, treatment
pressures, volumetric rates at which treatments will be performed,
configuration of the well bore and the number of treatments to be
performed per day. Initial treatments conducted by the applicant at
67%/33% N.sub.2 /CO.sub.2 have reflected primarily convenience and
cost of product.
The invention is further illustrated by the following examples:
EXAMPLES
A gas well located in township 17 Range 20 West of the fourth
meridian in Alberta, Canada was completed with 114.3 mm casing to a
depth of 587 meters. The Belly River (gas) zone was perforated from
587 to 610 m. All completion fluid was removed from the well prior
to commencement of treatment.
One liquid carbon dioxide (CO.sub.2) bulker containing 55.0 m.sub.3
of liquid CO.sub.2 at approximately 2.0 MPa and -20.degree. C. was
connected to two high pressure frac pumpers through a pressurized
liquid CO.sub.2 blender. The liquid CO.sub.2 blender was loaded
with approximately 5 tons of 20/40 mesh sand prior to being
pressurized with liquid CO.sub.2. Three industry conventional
nitrogen pumpers containing approximately 4000 m.sup.3 of nitrogen
gas (S.T.P.) each were connected in parallel with high pressure
frac lines (pipe). The high pressure frac lines from the nitrogen
pumpers joined the high pressure frac lines from the liquid
CO.sub.2 prior to the lines being connected to the wellhead. One
way check valves were installed in the lines to ensure that one set
of equipment would not overpower the other set.
Prior to the connection of the treatment lines to the wellhead a
wire line company ran a combination pressure, temperature, gamma
ray, and density tool to the bottom of the well to establish
initial conditions. On completion of the wireline survey the
treatment lines were connected to the wellhead. The pressurized
liquid CO.sub.2 blender, frac pumpers and lines were then cooled
with liquid CO.sub.2 vapour. All surface lines and pumpers were
then pressure tested.
The treatment was initiated by using 6.3 m.sup.3 of liquid CO.sub.2
to fill the well and then using 3.7 m.sup.3 of liquid CO.sub.2 to
create a fracture in the formation at a rate of 6.5-6.3 m.sup.3
/minute and pressures of 13.7-10.8 MPa on surface and 12.0-11.0 MPa
bottomhole. At this point pumping was stopped and both surface
pressures and bottom hole pressures, temperatures and densities
were monitored. The gathered data showed a fracture gradient of 9.8
kPa/m, a total friction gradient of 12.4 kPa/m which included
approximately 700 kPa of perforation--near well bore friction.
The treatment was reinitiated using 10 m.sup.3 of liquid CO.sub.2
to recreate the fracture at a rate of 6.2-5.9 m.sup.3 /minute and
pressures of 11.2-10.3 Mpa surface and 11.0 Mpa bottomhole. Again
the pumping was stopped and variables monitored. The gathered data
showed a fracture gradient of 10.0 kPa/m, a total friction gradient
of 10.7 kPa/m which included approximately 500 kPa of
perforation--near well bore friction.
A third mini frac was then pumped with liquid CO.sub.2 at a rate of
2 m.sup.3 /minute and nitrogen added at 480 m.sup.3 /min (S.T.P.).
The nitrogen rate was calculated based on bottomhole pressure and
temperature to be 4.0 m.sup.3 /minute volumetrically for a total
volumetric rate of 6.0 m.sup.3 /m. This part of the treatment was
conducted at 8.0-8.5 MPa on surface and 10.6 MPa bottomhole pumping
4.6 m.sup.3 of liquid CO.sub.2 and 1606 m.sup.3 (S.T.P.) of
nitrogen. The gathered data showed a fracture gradient of 10.5
kPa/m, ay total friction gradient of 2.5 kPa/m which included
approximately 50 kPa of perforation--near well bore friction.
During the treatments the pressure required to move the liquid
CO.sub.2 from the bulkers was maintained by gaseous nitrogen
supplied by a "Nitrogen Tube Trailer". The "Nitrogen Tube Trailer"
is a series of pressure vessels that carries approximately 3500
m.sup.3 (S.T.P.) of gaseous nitrogen up to 18.0 MPa and can be
regulated to supply any given constant pressure.
The wire line with the bottom hole recording devices was pulled to
surface and disconnected from the wellhead prior to the
commencement of the sand laden treatment.
The sand laden fracture treatment was then initiated with a pad
consisting of 4.5 m.sup.3 liquid CO.sub.2 pumped at 2.0 m.sup.3
/minute and 1620 m.sup.3 (S.T.P.) N.sub.2 pumped at 480 m.sup.3
(S.T.P.)/minute. Surface treating pressures dropped from 9.1 MPa to
8.6 MPa during the pad. Sand addition was conducted at the liquid
CO.sub.2 blender as per the outlined Schedules I and II, pumping
5.0 tonnes of 20/40 mesh at concentrations of 300 kg/m.sup.3 to
1550 kg/m.sup.3 to the liquid CO.sub.2 stream and calculated
bottomhole effective concentrations of 100 kg/m.sup.3 to 500
kg/M.sup.3. The CO.sub.2 -sand slurry rate was increased during
sand addition in order to maintain a constant N.sub.2 /CO.sub.2
ratio of 2.0 and increase slurry velocities to aid in proppant
movement at higher concentrations. The pressures during proppant
addition were 8.8 MPa to 8.0 MPa.
______________________________________ PROPPANT FLUID SCHEDULE I
Cum Fluid Sand Cum Fluid Stage Conc. Sand Sand Stage (m.sup.3)
(m.sup.3) (kg/m.sup.3) (kg/Stage) (kg)
______________________________________ Pad (Liquid CO2/N2) 14.0
14.0 Start 20/40 Sand 16.0 2.0 100 200 200 Increase 20/40 Sand 18.0
2.0 200 400 600 Increase 20/40 Sand 21.0 3.0 300 900 1,500 Increase
20/40 Sand 24.0 3.0 400 1,200 2,700 Increase 20/40 Sand 28.6 4.6
500 2,300 5,000 Flush (Liquid CO2/N2) 31.8 3.2
______________________________________
______________________________________ PROPPANT CO.sub.2 SCHEDULE
II Cum Fluid Sand Cum Fluid Stage Conc. Sand Sand Stage (m.sup.3)
(m.sup.3) (kg/m.sup.3) (kg/Stage) (kg)
______________________________________ Pad (Liquid CO2) 4.5 4.5
Start 20/40 Sand 5.2 0.7 303 200 200 Increase 20/40 Sand 5.9 0.7
606 400 600 Increase 20/40 Sand 6.9 1.0 909 900 1,500 Increase
20/40 Sand 7.9 1.0 1212 1,200 2,700 Increase 20/40 Sand 9.4 1.5
1515 2,300 5.000 Flush (Liquid CO2) 10.5 1.1
______________________________________
The slurry mixture was finally displaced to the perforations by
pumping 1.1 m.sup.3 of liquid CO.sub.2 at 2.0 m.sup.3 /minute and
400 m.sup.3 (S.T.P.) gaseous nitrogen at 480 m.sup.3
(S.T.P.)/minute. The pressures during the flush ranged from 7.9 MPa
to 7.7 MPa. The gathered data showed a fracture gradient of 10.5
kPa/m, a total friction gradient of 1.5 kPa/m.
Additional treatments have been performed in the same area all
placing a minimum of 5 tonnes of 20/40 proppant in formation. The
initial treatment was 100% liquid CO.sub.2 and the following
treatments were a 67%/33% mixture of N.sub.2 /CO.sub.2. The 100%
liquid CO.sub.2 treatment placed 5 tonnes of proppant at
concentrations of up to 500 kg/M.sup.3 in formation. The mixture
treatments have placed up to 7 tonnes in formation at
concentrations of up to 700 kg/M.sup.3.
Observed decreases in surface treatment pressures with the
gas/CO.sub.2 treatment are apparently due to the reduced
coefficient of friction of the co-mingled fluid compared to pure
liquified CO.sub.2. The reasons for reduced leak-off into the
formation being treated are not fully understood but could be due
to the fact that the added gas requires less energy than the
liquified gas to expand. This could generate more turbulent flow of
the leaked-off fluid creating a near-fracture pressure zone that
aids in leak-off control. Obviously, any drop in fluid loss rates
increases the chances of successfully placing total specified
proppants into the formation.
Applicant has found important economic advantages attendant to the
method as described above. For the well owner, savings are realized
due to the decreased amounts of liquid CO.sub.2 required, nitrogen
being considerably less expensive than liquid CO.sub.2, and the
complete or near complete elimination of chemical additives. Fewer
CO.sub.2 bulkers are required meaning lower transportation charges
and the number of transports required to maintain the liquid
CO.sub.2 product is similarly reduced. Pumping charges are directly
proportional to the liquid pumping rate and surface pumping
pressures. As aforesaid, it has been discovered that co-mingling of
gas with the liquid CO.sub.2 results in a drop in the required
liquid, pumping rate and in surface treatment pressure, thereby
adding substantially to the economic benefits as a result of
reduced power requirements.
From the service company's perspective, the present method should
expand the liquid CO.sub.2 fracture market by supplying a less
expensive method useful at shallow and greater depths. The improved
logistics of the process due to reduced CO.sub.2 transport ought to
permit an increase in the maximum number of treatments per day
which will additionally enhance savings and margins.
The above-described embodiments of the present invention are meant
to be illustrative of preferred embodiments of the present
invention and are not intended to limit the scope of the present
invention. Various modifications, which would be readily apparent
to one skilled in the art, are intended to be within the scope of
the present invention. The only limitations to the scope of the
present invention are set out in the following appended claims.
* * * * *